In the drilling of well bores in the oil and gas industry it is common practice to use down hole motors to drive a drill bit through a formation. Down hole motors used for this purpose are typically driven by drilling fluids pumped from surface equipment through the drill string. This type of motor is commonly referred to as a mud motor. In use, the drilling fluid is forced through the mud motor, which extracts energy from the flow to provide rotational force to a drill bit located below the mud motors. There are two primary types of mud motors: positive displacement motors (“PDM”) and turbodrills. A less common down hole motor may be driven by electricity. As used herein, a “down hole motor” refers generally to any motor used in a well bore for drilling through a formation. As used herein, a “motor portion” refers to the portion of the down hole motor that generates torque.
A PDM is based on the Moineau principle. Drilling fluid is forced through a stator. An eccentric rotor is located inside the stator. Drilling fluid circulating through the stator imparts a rotational force on the rotor causing it to rotate a shaft. This rotational force is transmitted to a drill bit located below the PDM.
A turbine uses one or more turbine stages to provide rotational force to a drill bit. Each stage consists of a non-moving stator and a rotor mechanically linked to a shaft. The stator directs the flow prior to entrance into the rotor in order to provide more rotational force. Drilling fluid passing between blades on the rotor causes the rotor to rotate the shaft and the drill bit located below the turbine.
During drilling, the drill bit may get stuck in the formation. If a bit-sticking issue develops and the drill bit cannot be freed, the entire bottom hole drilling assembly may be lost in the well bore. If this occurs, in addition to the value of the lost tools, a sidetracking trip to deviate around the stuck assembly is often necessary. This is an extremely expensive consequence.
In the event that a drill bit becomes stuck, it is a common practice to apply a sufficiently large torque generated at the surface through the entire drill string to free the drill bit. This would not be effective if down hole motors are used because the configuration of down hole motors prevents torque from being transmitted from the surface to the drill bit. Typically, the housing of a down hole motor is connected to the drill string at the upper end. The shaft contained within the housing is not rotationally linked to the housing in a manner that allows torque transmission from the drill string to the shaft (i.e. rotate freely relative to each other), and it is the lower end of the shaft that is connected to the drill bit (some tools may be in the drill string between the shaft and the drill bit). As a result, the only torque that can be transmitted to the stuck drill bit is the torque that the down hole motor is able to produce. What torque can be transmitted by the down hole motor is very little relative to what can be transmitted from a surface rotary tool, and is typically insufficient to free the stuck drill bit.
In the prior art, one method known for transmitting torque from the motor housing to the internal shaft is through the use of locking balls. The locking balls are metal spheres that are dropped from the surface into the down hole motor where they are lodged in specific cavities between the housing and shaft. These cavities are shaped such that when the housing is rotated, the locking balls pinch against the shaft. This locks up the housing with the shaft. This allows for a connection in the work string above the down hole motor to be backed off, leaving the down hole motor, the drill bit, and other components in the well bore. The components left in the well bore must then be side tracked around to continue the drilling of the well bore.
There are several limitations to this prior art method. Even if successful in their function, the locking balls still require leaving components in a well bore, which must then be fished out or side tracked around. Both of which cost a substantial amount of time and money. Further, this approach is sometimes unable to sufficiently lock up the housing to the shaft, which can prevent backing off a connection above the down hole motor. This would result in more expensive, difficult, and time consuming fishing operations. A further limitation to the use of locking balls is that they may not always be deployable based on the components in the drill string. For example, many designs of measurement while drilling (“MWD”) tools, which are deployed above the down hole motors in the drill string, do not allow for locking balls to pass through them.
What is still needed are down hole motors and methods for preventing a drill bit from becoming stuck and for freeing a stuck drill bit. Further, it is desirable to be able to apply torque through the housing to the shaft of the down hole motor as needed without the use of objects dropped into the well bore such as locking balls.